NexTier Oilfield Solutions Inc. (NYSE:NEX) Q4 2022 Earnings Call Transcript

NexTier Oilfield Solutions Inc. (NYSE:NEX) Q4 2022 Earnings Call Transcript February 16, 2023

Operator: Good morning, and welcome to the NexTier Oilfield Solutions Fourth Quarter 2022 Conference Call. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. For opening remarks and introduction, I would like to turn the call over to Mike Sabella, Vice President of Investor Relations for NexTier. Please go ahead.

Mike Sabella: Thank you, operator. Good morning, and welcome to the NexTier Oilfield Solutions’ earnings conference call to discuss our fourth quarter 2022 results. With me today are Robert Drummond, President and Chief Executive Officer; Kenny Pucheu, Chief Financial Officer; and Kevin McDonald, Chief Administrative Officer and General Counsel. Before we get started, I would like to direct your attention to the forward-looking statements disclaimer contained in the news release that we issued yesterday afternoon, which is currently posted in the Investor Relations section of the company’s website. Our call this morning includes statements that speak to the company’s expectations, outlook or predictions of the future, which are considered forward-looking statements.

These forward-looking statements are subject to risks and uncertainties, many of which are beyond the company’s control, which could cause our actual results to differ materially from those expressed in or implied by these statements. We undertake no obligation to revise or update publicly any forward-looking statements, except as they may be required under applicable securities laws. We refer you to NexTier’s disclosures regarding risk factors and forward-looking statements in our annual report on Form 10-K, subsequently filed quarterly reports on Form 10-Q and other Securities and Exchange Commission filings. Additionally, our comments today also include non-GAAP financial measures. Additional details and a reconciliation to the most directly comparable GAAP financial measures are included in our earnings release for the fourth quarter of 2022, which is posted on our website.

With that, I will turn the call over to Robert Drummond, Chief Executive Officer of NexTier.

Robert Drummond: Thank you, Mike, and thanks to everyone for joining the call today. 2022 was a strong year for NexTier. While we will not rest on our past successes, I do want to take a moment to reflect. We started 2022 by asserting our view that the frac market was tight and that frac equipment will become harder to fund, a view that was far from the consensus at the time. Indeed, frac quickly emerged as one of the main bottlenecks in the U.S. shale oil and gas market. Against this macro backdrop, with strong demand and limited supply for our services, our pricing outlook improved considerably as the year progressed. Importantly, we were able to deliver strong results for our investors, while also delivering best-in-class service for our customers.

To all our hard-working employees and their families that made last year possible, thank you for contributing to the success of our company. I could not be prouder of what we accomplished together. At NexTier, we are committed to sharing in the success in investing in our people as we strive to make this a destination for the hardworking men and women of our industry, who are looking to build a long and prosperous career. During 2022, our success extended beyond just the core frac operation to each of our service lines with profitable growth in wireline, cement, power solutions and last-mile logistics. But despite the progress we made last year, our business still has not returned to pre-COVID net pricing, and we are still looking to recoup prior investments we made to improve efficiency.

Our prior investments must be combined with supported fundamentals if our industry can be expected to drive the next leg of process improvement and fully reflect the value we can create for our customers. On the macro front, we believe the cycle has only just begun with a setup in 2023 that is as good as what we saw in 2022. We believe demand for frac fleets today exceeds supply by 20 to 25 fleets with as much as 10% of horsepower demand going unmet, which has allowed us to raise price this year already. We also have customers that are inquiring about 2024 work now. But fully satisfying demand of our customers had its challenges. Our supply chain remains stretched with a backlog for parts that is substantially higher than normal. We’ve seen little progress so far in correcting the situation.

While some argue that current economics will stall attrition, the reality is that supply chain challenges, capital discipline and inflation are more likely to cause attrition to accelerate and new builds to delay further. In fact, delivery of our own electric fleet has been delayed in the Q2. At NexTier alone, we plan to decommission roughly 150,000 horsepower over the next 18 months. Meaning, within our capital budget framework of 8% to 9% of revenue, our capacity will remain relatively flat this year. We will continue to allocate capital to the highest return investment. And, as we show on Slide 11 of our updated investor presentation, investing in these older assets no longer meets our hurdle rate. It makes more sense for us to invest in new equipment than to continue to deploy capital into these older obsolete assets.

We do not believe we are alone in this attrition narrative. Even with the new builds, we see a challenged path to increasing industry frac capacity, which should lengthen the cycle and solidify another round of price increases. At the same time, and as we show on Slide 12, a bifurcated industry fleet with a steep equipment cost curve is allowing our natural gas fueled assets to earn a premium return. These differentiated returns, supported by the fuel cost arbitrage, should last several years as the industry fully transitions to next-generation equipment, a process that will likely take over seven years at the current newbuild cadence, with more than half of industry capacity still legacy diesel fleets. The demand side is supported by what we see as an underinvested oil and gas market that needs to increase production to avert a global energy supply crisis.

U.S. shales’ role will no doubt be critical in balancing global commodity markets, but our customers are restricted by their own capital discipline, as well as the availability of equipment like frac. We do not believe shale is prepared to quickly answer the global call, which should lengthen the demand cycle for our services as the world searches for more oil and gas. For NexTier, we believe we’re on a path to additional profitability in 2023 and beyond. We entered this year still roughly 10% below pre-COVID net pricing for our frac services and we will look to recapture that throughout the coming year, some of which we’ve already realized. We also see opportunities to grow our wellsite integration offerings and invest in high-return projects that support efficiency in our core frac operations.

Even as the strong macro environment plays out, we will continue to lead our industry in disciplined behavior and use our returns to reward our shareholders. We’ve established a track record of delivering strong free cash flow, high return on investment and capital efficient growth. We will continue to focus on maximizing returns on capital and returning capital to shareholders. We believe this will be the winning strategy for our company and our investors. While our industry fundamentals remain strong, we would be remiss to ignore the growing dialogue around weakness in the near-term natural gas fundamentals. For NexTier, our largest natural gas exposure remains in the Marcellus. Takeaway capacity has constrained activity in that basin for some time now and activity there has been relatively steady over the past couple of years compared to other gas basins.

Coupled with the lower breakeven well economics, we expect Marcellus activity to remain relatively steady despite the drop in natural gas prices. Because of this, we think the Haynesville will take the brunt of any activity decline. History suggests worst case is perhaps a 50% decline in Haynesville activity, which would imply as many as 14 frac fleets could be released from that basin, a scenario that would result in a significant decline in basin production. But we want to be crystal clear, we fully believe the fundamental supplied nature of the frac market in the oil basins could easily absorb these fleets. Even in this scenario, when taken into consideration current unmet demand, modest demand growth in oil basins and the planned frac fleet additions, we believe total utilization is likely to remain balanced.

Even a small amount of attrition would keep the energy fully sold out through 2023 and we believe attrition is inevitable as evidenced by our own actions. Our macro view has always taken a more conservative view on near-term rig count additions due to our understanding that frac fleets are the bottleneck to production growth. So, while we are watching the natural gas fundamentals just like everyone else, we view the potential disruption as a relatively minor threat, given our view that the overall U.S. land frac market is still undersupplied and likely will be throughout 2023. It is important to note that we only have a small exposure to the Haynesville with just two fleets operating in that basin today. Additionally, we’re not hearing any commentary from our natural gas customers about slowing the pace of completions.

Further, low gas prices increased the cost advantage of our natural gas fuel fleets, which could solidify demand for those premium assets and raise the value of our Power Solutions business. Nevertheless, even as we see this cycle continuing, we are nimble and can respond quickly to unforeseen changes. We have a sticky customer relationships, and we will always prioritize a strong balance sheet with substantial liquidity. Now to our results. We saw improved profitability and return sequentially even in a counter seasonal period. Net income of $133 million improved 27% from the prior quarter and was 15% of revenue. Our net income per diluted share was $0.52. Total revenue of $871 million was down 3% sequentially, but was 71% higher than the same quarter last year.

Our adjusted EBITDA was $213 million, was up 9% from Q3. We effectively managed our decremental margins on a sequential basis and we managed to shift to higher margin work with better returns. We also continued to generate very strong free cash flow, generating $93 million in Q4 even as we funded an Alamo earnout payment. During Q4, we repurchased 11.5 million shares for $113 million under our $250 million shareholder return program, funded entirely with free cash flow and cash on hand. For the full year 2022, we more than doubled our revenue with adjusted EBITDA nearly six times greater. Most importantly, we achieved this strong growth while staying very disciplined with our capital allocation and generating $295 million in free cash flow.

Since the very start of the recovery, we saw that winning this cycle was going to require a different approach compared to prior cycles. We’ve been steadfast and our message that our goal is to balance future growth needs demanded by our customers with returns and free cash flow needs demanded by our investors. We’re happy to see this strategy being repeated by many of our peers across the industry. Capital discipline has become a common theme in the industry, which should lengthen the duration of the cycle. We’re proud of our success in balancing these two strategies and we have high conviction that this is the best path forward for our company and our investors. As you see on Slide 15, we’ve achieved our growth in a very capital-efficient manner.

On Slide 16, we show that we achieved our growth over the past year while deploying significantly less capital relative to our peers. For 2022, our 30% return on invested capital has improved significantly over the past year. In the fourth quarter, we delivered an annualized ROIC of 46%. ROIC is one of our highest priorities we consider whenever we make an investment decision. Maximizing returns require smart and opportunistic capital allocation. We invested counter cyclically, which allowed us to create additional value during the early parts of the cycle, and we continue to rationalize our asset base. We sold $50 million of non-core assets last year and redirected the funds to areas where we can create better value for our shareholders. We believe our return should improve significantly again in 2023 and have the potential to stay high for multiple years.

We expect strong demand will continue. And on the supply side, the market remains undersupplied and consolidated. Additionally, growing capital discipline in our industry and equipment and parts availability are restricting our ability to add and maintain equipment. Finally, bifurcation and equipment quality is elevating returns as the industry undergoes a lengthy conversion to natural gas. During 2022, we reported earnings per diluted share of $1.26. Our share price today is just seven times our 2022 earnings per share, and considering we expect EPS growth again in 2023, we believe our forward-looking price to earnings ratio is even lower. We generated $295 million of free cash flow in 2022 and our expectation is that will increase — that we will increase our cash flow to at least $500 million in 2023.

We see free cash flow conversion over 50% this year and we still see a path to growing our adjusted EBITDA 40% to 50% relative to 2022. Ultimately, the goal of this strategy is to maximize value creation for our shareholders. Last quarter, we presented a detailed capital allocation strategy that rest on two foundational pillars: we will prioritize a net debt zero capital structure to ensure our business remains nimble through the cycle; and we will look to invest 8% to 9% of our revenue in CapEx annually, which we believe is sufficient for us to maintain service quality and market share in our core frac business, while slowly transitioning the rest of the fleet to natural gas powered and funding growth in our wellsite integration strategy. On top of this foundation, since what we believe is a durable free cash flow profile, we will return at least half of this free cash flow to shareholders through a process that we started in 2022.

Through February 14, and including the amount we used in Q4, we’ve repurchased 14.4 million shares for $139 million, bringing the total to nearly 6% of the shares that were outstanding prior to the buyback. After funding our shareholder return commitment and reaching our capital structure goal, we believe that we have optionality on roughly $200 million in cash through the end of this year. We remain interested in M&A, including both for further consolidation of the frac market as well as other avenues to grow our successful wellsite integration platform. We have a very strong M&A track record as been demonstrated by our recent acquisitions of Alamo and CIG Logistics, both of which easily outperformed initial expectations and have become core to our company.

But we will continue to be prudent and will act on transactions that make sense for our shareholders. If no attracted deals are found, we can pivot to use the cash to further strengthen our balance sheet or expand the shareholder return program. We remain committed to maximizing the value every dollar of capital in all phases of market cycles guided by our sustainable capital allocation program. We believe the significant use of cash to repurchase shares should demonstrate our dedication to our strategy as well as our conviction in the long-term outlook for our business and the belief that our equity is significantly undervalued. The prior cycle OFS playbook, which was guided almost solely by EBITDA growth and relied in — on indefinitely capitalizing one-year returns in new build economics while ignoring industry supply and demand fundamentals, did not work.

We believe our balanced strategy better served the company and our shareholders, and we will continue to chart this new course. We have strong conviction that capital discipline and a focus on sustained returns and capital efficient growth will be the winning formula in this cycle. We are bullish that the cycle is in its early stage and we are prepared to deliver strong value creation and return capital to our shareholders the entire time. I’ll now pass the call over to Kenny to discuss the fourth quarter results in more detail.

Kenny Pucheu: Thanks, Robert. Fourth quarter revenue totaled $871 million compared to $896 million in the third quarter. Revenue decreased 3% sequentially, which was in line with our guide. We had strong execution and pricing continued to strengthen during the quarter, which was offset by seasonal downtime as well as lower product sales. We continue to operate very efficiently with near company record pumping hours per fleet on average even with seasonal disruptions. Revenue declined in our Completion segment, while the Well Construction and Intervention Services segment revenue improved on strong demand and solid operational performance. Total fourth quarter adjusted EBITDA was $213 million, an improvement from $195 million last quarter.

We increased profitability despite lower revenue based upon several factors. First, we saw a shift in work to higher efficiency, higher margin jobs during the quarter. This lower revenue more profitable work is a function of aligning ourselves with like-minded customers that focus on efficiency, integration and value creation. This realignment is also serving us well in 2023. Second, while holiday downtime was a factor in our results, we managed costs to help minimize the impact on our profitability. And third, the investments we are making to improve our efficiency and cost structure are working. These investments, such as expanding the functions of our NexHub Digital center, upgrading ancillary equipment around our frac fleet and improving last-mile efficiency, goes straight to the bottom-line and we’re critical in the quarter-on-quarter improvement.

In our Completion Services segment, fourth quarter revenue totaled $830 million compared to $858 million in the third quarter, a sequential decrease of approximately 3%. Completion Services segment gross profit improved to $227 million even on lower revenue as we upgraded the quality of work and effectively manage costs. In our Well Construction and Intervention Services segment fourth quarter revenue totaled $41 million, an increase of 7% compared to $38 million in the third quarter. Gross profit totaled $10 million, an increased from $8 million in the third quarter as our cement operations showed strong improvement. Fourth quarter selling, general and administrative expense totaled $37 million, flat compared to the third quarter. And excluding management net adjustments of 7 million, adjusted SG&A expense totaled $30 million.

EBITDA for the fourth quarter was $200 million. When excluding management net adjustments of $13 million, adjusted EBITDA for the fourth quarter was $213 million. Management adjustments include $7 million in stock comp, with other items totaling to net of $6 million, which are non-recurring in nature. Approximately $6 million of total net management adjustments were cash related. Now on the balance sheet. We exited the fourth quarter with $218 million in cash, down from $250 million at the end of the third quarter. We exited the fourth quarter with total available liquidity of approximately $634 million. Our liquidity was comprised of cash of $218 million and $415 million available on our asset-based credit facility, which remains undrawn. Total debt at the end of the fourth quarter was $361 million, net of debt discounts and deferred financing costs and excluding finance lease obligations.

We have no term loan maturities until 2025. Net debt at the end of the fourth quarter was approximately $143 million, an increase from $115 million at the end of the third quarter. This sequential increase in net debt is a function of the use of cash as part of the share repurchase program. Cash flow from operating activities was $144 million for the quarter. Profitability strengthened, while the sequential decline is a function of the Alamo earnout payment during the quarter. We continue to aggressively manage our working capital and saw solid improvements in our cash collections. Our cash used in investing activities was $51 million during the fourth quarter, and CapEx totaled $79 million, mostly driven by normal maintenance, investments in the next phase of our Power Solutions growth and proactive investments to increase our inventory to spare major components, such as engines and transmissions, as we look to minimize the impact of the tight supply chain.

We also funded the replacement pumps for the portion of the fleet we lost so far in Q3, which was entirely offset by insurance proceeds. This resulted in overall positive free cash flow of $93 million for the fourth quarter. Now, on the outlook. Customer demand was very strong as we entered 2023, and this has continued through Q1. We had a very encouraging start to the New Year, with very little impact from normal startup issues that can arise after the holiday slowdown. As is always the case, winter weather will have an impact on our Q1. For the first quarter, we expect total revenue will be up at least 6% sequentially. Consistent with previous guidance, our 2023 CapEx budget remains at $350 million, which included in attrition will result in relatively flat horsepower deployment through the year.

We expect our budget to be first-half weighted and expect CapEx to decline in the back half as we plan to invest early in the year to maximize returns. We see free cash flow of at least $500 million in 2023. We are excited about the company we have built. We’ve made smart capital allocation decisions that have positioned us to outperform our peer groups on returns — free cash flow early in the cycle. We plan to continue to win through our focus on balancing high return investments and dedication to capital discipline. As we pointed out in our updated investor presentation, the oilfield services sector is healthy. Returns at most of our peer group are exceeding the cost of capital for the first time in many years and the sector is generating meaningful operating margins.

Contrary to prior cycles, the industry is prioritizing shareholder returns, which should mean a longer or durable return profile for next year in our peers and thus a more investable industry. We believe current equity valuations are not indicative of our sustainable earnings profile. We see no indication of a slowdown with macro fundamentals expected to remain strong for multiple years. I’ll now turn it back to Robert for closing remarks.

Robert Drummond: Thanks, Kenny. As we announced earlier this week, we recently added an Independent Director. Leslie Beyer has agreed to join our team and will be an important voice for the company as we enter the next phase of our development. Leslie is the CEO of the Energy Workforce & Technology Council, the largest energy technology and services association in the world. She brings with her a wealth of oil and gas knowledge and expertise and we’re so delighted to have her voice in our board room. Now let me close with a few takeaways. First, we’re very excited for 2023. Industry fundamentals are strong as they were last year and the tightness now is far better understood. Given the sold-out nature of the frac market, customers are actively looking to align themselves with the most reliable partners as they look to maximize their own capital efficiency.

Several of our customers are already starting conversations now for 2024 work. Our operational excellence puts us high on that list. We have repositioned our footprint commercially and geographically to allow strong partners, which should mean higher profits in 2023. Second, our wellsite integration strategy is a differentiator that relies heavily on value creation and synergies. For NexTier, our integrated offering either lowers the total cost to operate at completions wellsite or raises efficiency, and, in most cases, both. This value creation allows us to earn strong returns, while also offering the customer a superior product. If we do not see a path to process improvement, we do not see the need to invest our capital dollars in the service.

Finally, we still see some investors and analysts discussing the investment strategy for OFS in the same context as prior more growth-oriented cycles. The industry has changed. Durable returns, earnings per share and free cash flow are increasing in importance and must be considered alongside EBITDA growth. We see this as the best strategy to attract the next generation of investors back to oilfield services. At NexTier, we’re doing our part to lead the industry into this next phase. With that, we’d now like to open the lines for Q&A.

Q&A Session

Operator: Thank you. And we will now begin the question-and-answer session. Our first question today is going to come from Scott Gruber of Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. Great execution this quarter.

Robert Drummond: Thank you, Scott.

Kenny Pucheu: Thanks, Scott. Good morning.

Scott Gruber: I think I want to start on your comments regarding the unmet demand in the oily basins. Obviously, as you mentioned, the market is concerned about gas directed activity migrating out into the oily basins. So, just some color on how you dimension the magnitude of that unmet oil demand? Are you looking at DUC counts? Is it based on customer conversations? A blend of the two? Just some color on how you arrived at the 20% to 25%?

Robert Drummond: Well, I’ll be glad to walk you through that. If you go back to Q3, we were saying then that frac demand growth was higher than frac supply growth and that frac supply was already at that point the bottleneck for U.S. production growth and a little bit contrary to the fact at that particular time that the current rig count was increasing the DUC count even back then. You combine that with the fact that the frac supply chain is stressed and that attrition for the frac fleet is very real. And that’s the kind of the backdrop for it. But certainly, any kind of projection that you put on macro frac — supply demand has to be built around. What is the macro for oil and gas? And for oil, I think the near-term narratives are around recession and inflation impact, China, Russia, the U.S. land natural gas price and also maybe the SPR replacement balanced against the structural long-term undersupply scenarios.

So, we’re not going to try to predict oil price, but — when we look at what our customers are budgeting and we look at our view of the long-term kind of runway for oil, it’s very supportive. So, then you kind of take and drop that into frac supply and demand. We exited last year about 272 fleets operating, and we thought in a market that needed about 20 to 25 more fleet. And that is the beginning of taking a look at what you would project it to look like at the end of ’23. So, there’s been a lot of discussion about drilling rig additions in ’23. That number continues to come down over the last few months, and we’ve been very conservative about that because we always knew that frac was more or less the bottleneck. So, we just take a slight increase in drilling rig count and the whole basins for next year generates a demand for about 10 more frac fleets.

And then, we take a look at that. At the Haynesville side of this scenario, and — there’s been a lot of discussion that we mentioned in our prepared remarks that we see that there’s going to be some activity decline, we believe. Even though the customers are not saying it yet, we believe there’s going to be some decline in the Haynesville more than any other gas basin. So, we went back and looked historically last two down cycles back in 2016 and 2020, gas price around $2.00. We saw 50% reduction in the frac fleets in the Haynesville. That’s about 14, it’s not dramatic to the macro, but you got a few additional oil rigs on the demand side and a few less gas rigs. Take a look at the supply side, we’ve spent a lot of effort to stay on top of what we believe is about 29 new builds and reactivations that coming into the market in ’23 throughout the year.

A significant number of those hit in Q1 as it was projected. But there’s a lot of pressure pushing those to the right as well. I mentioned in our prepared remarks, in fact, our electric fleet is getting pushed into Q2. But if you just put any kind of conservative attrition number on that side of the supply side, even as little as 5%, which is that — we think is much more than that, but just say 5%, that projects into a balanced market as you exit 2023. So, we like the way that shift shakes up. And some of that stems around if you believe DUC count has been increasing or not, and the EIA recently kind of came out with their last three numbers for November, December and January, and they were 14, 35 and 42 DUCs per month. Our own numbers are a little bit higher than that.

And we believe that even in February, we’re going to see the DUC count in the U.S. on a macro increase by between 40 and 50. So, I’m glad you asked that question. I really wanted to be able to address what we’ve been hearing kind of in the press a little bit about second half pressure. We just don’t see it that way. And that’s the reason. That’s as detailed guidance I could probably get to.

Scott Gruber: No, I appreciate all that detail. And I do want to turn to the Power Solutions business, which is set to offer a lot of value to clients in the current market with this widening gas diesel spread. What are you hearing from your clients on incremental demand for your Power Solutions offering? And is it something that you’re contemplating increasing spending on this year, shifting some of the budget more that way? Just kind of some of the latest conversations on your expansion in that business and customer appetite for more?

Robert Drummond: Yes, I’ll start in the back end of that. Thanks for asking. Power Solutions has been something we’ve been very proud of. We built that business to fuel ourselves and help us get to maximum displacement of diesel with CNG for our own frac fleets in the beginning. And as far as how much growth will have, I think the exit of ’22 versus the exit of ’23 will be more than double. And it’s a very robust business that we’ve been able to keep sold out ahead of delivery. And we’re making a notch up in Q1 on deployed fleet, substantial notch up, and then again in the back half of the year. So, we’re continuing the investment into that high return business. But that business is very valuable to us, not only in the sense of the P&L associated with the CNG fueling business, but also the efficiencies it adds to the overall frac franchise.

The way we have Power Solutions combined in an integrated modeling location, our frac fleets, dual fuel — diesel frac combination fleets displays natural gas at a much higher rate than the average in the market, as being told to us by our customers. So, yes, it helps us capture the fuel arbitrage to a greater extent, adding returns to our frac fleet as well as its own P&L. So, it’s been a thing that we’re going to continue to go and we even would say openly that we’d like to keep looking inorganically around that kind of model to continue to grow that business with robust cash flow we have.

Scott Gruber: I appreciate that color, Robert. I’ll turn it back. Thank you.

Robert Drummond: I appreciate it. Thank you.

Operator: Our next question today will come from Stephen Gengaro with Stifel. Please go ahead.

Stephen Gengaro: Thanks. Good morning, everybody.

Robert Drummond: Good morning.

Stephen Gengaro: Two things for me. One, I guess, follow-up on Scott’s question. When you guys laid out in your Analyst Day that $7 million of cash savings per fleet, I think it’s $5 million of EBITDA, $2 million of cash flow, where do you stand on that initiative? How much of that is flowing through this pretty healthy annualized EBITDA per fleet number right now? And how much is — how much should we think about maybe being additive over the next 12 months?

Robert Drummond: We can only move as fast with that comprehensively as we can grow the capacity of Power Solutions. But we got plenty of capacity in wireline and plenty of capacity in our last-mile logistics. So, each one of the components of the integration are on a different run rate, I’d say. But we continue to eke — move it up slightly. I was saying last quarter, we were probably in a third inning, something like that. Some fleets were 100% and some were 10% or something. And that’s something that — as we moved from 2022, made the decisions about who we were going to partner with in 2023, that we took into consideration. We moved as many — over 25% of our customer base changed between December and January in tune with that.

Sometimes you take a step forward with integration and sometimes you take a step backward. But in the cases where we actually took a step backward from an integration standpoint, we took a position that gave us better returns overall. And then, we can turn around and build on the integrations as we get deeper into the year, because we found, once we get a toehold, typically it doesn’t take very long to begin to demonstrate the value of the integrated model, and we’re able to build upon it. So, I’d still say very early days, but we expect to make a lot of progress on that in 2023. In fact, we’re in the process of a slight organizational tweak to enable the management in the field to be able to better align and drive that process. So, I’m excited about the upside potential of it.

Stephen Gengaro: Great. Thank you. And then, my follow-up is probably two parts. But one is when you think about the first quarter, can you just give us your expected fleet count? And based on your revenue growth, it feels like there should be $15 million or $20 million of incremental EBITDA growth at reasonable incremental. Is that in the ballpark of what you’re thinking?

Robert Drummond: Yes, let me just kind of tell you kind of what things kind of flow a bit. More and more, we’re getting — it’s harder for us, I’d say, to talk about fleet allocations, when we’re really thinking about more horsepower allocations. You’re going to see a lot, I think, of — or some drift in our fleet count up and down going forward, I’d say forever, as we configure our fleet optimally, fleet to fleet, geography to geography, client to client, even though our horsepower, I expect to maintain flat, So, that’s one thing I’d say. And then, I would also say as we went into Q1, I don’t think I could say that I’ve ever been more pleased with the start we’ve had to a quarter. I talked about the turnover we had in customer base that began in December, it created a situation — we had the best month we probably ever had in January, and that’s usually not easy to pull off.

So, in February, you got a little bit of freezing weather days that hurt us in the Permian, but we’re off to a great start there. So…

Kenny Pucheu: Yes. And even with the weather impacts built in early Feb, we do see that top-line growth of at least 6% that we said. And I want to be clear, we’re expecting to grow profitability quarter-on-quarter. Whenever you look at that revenue growth, there’s going to be positive impact from pricing and operational performance and calendar improvements, and this is going to be partially offset by weather. We think that February actually costs probably about $25 million to $30 million on the top-line, but still again on that 6%. But with that being said, we expect profitability to continue to increase at a good pace quarter-on-quarter. And even with that February impact, we’re excited about the — continue to improve that.

Robert Drummond: And to the point about the fleet count, I’d just say we originally had said we have a fleet start in Q1 that electric fleet, but I would say that I would move that into Q2.

Stephen Gengaro: Okay, great. Thank you both.

Robert Drummond: Thank you.

Operator: Our next question will come from Luke Lemoine of Piper Sandler. Please go ahead.

Luke Lemoine: Hey, good morning, Robert and Mike.

Robert Drummond: Hey, Luke.

Luke Lemoine: Robert, I guess, with the pace of your buyback, it almost seems like you’re not going to leave any stock for anyone else to purchase. You just (ph) over half your authorization within four months. I guess, if we look at your free cash flow for this year and the pace of your buyback, it seems like this authorization could be finished in the next several months. And maybe a possible authorization increase, totally realize — an increased authorizations and Board decision. Would it be helpful if you can maybe just comment on the pace of buyback along with maybe your possible willingness to return well over 50% free cash flow to investors in a year, if you continue to see the stock undervalued.

Robert Drummond: Yes, Luke, we — I would start by — thank you for the question. I’ll start by saying that stay into the 50% return of free cash flow solidly in the plan. I would look at it like the commitment for the $250 million return for 2023, I would look at it — just that we got started early. The sale price on the stock was just too attractive and we went aggressively for. I think that when we look at re-upping it, I think that it will be in the context of that 50% of free cash flow and perhaps looking at it from maybe getting an early start on 2024. But no announcement now about any change to it other than that we’re on the same path that we’ve got to do what we’re going to be on. But I wouldn’t be surprised to see that evolve as we get into next quarter.

Kenny Pucheu: And I’ll just add, keep in mind we’re balancing all the elements of our capital allocation program. We’re going to have CapEx that will be somewhat front-end loaded as we invest early. On the buyback, we had a very aggressive start. You’d probably see some of that activity subside some. But what I would say is that at these pricing levels, we’re going to continue to be opportunistic.

Luke Lemoine: Okay. Got it. Thanks a bunch.

Robert Drummond: Thanks, Luke.

Operator: Our next question will come from Derek Podhaizer of Barclays. Please go ahead.

Derek Podhaizer: Hey, good morning, guys. I wanted to go back to the attrition conversation. Just maybe expand on the different components that you’re seeing? I mean, there’s definitely many forms to what attrition is. We’ve been seeing your deployed fleet count come down a few over the last couple of quarters. You’re talking about 29 fleets coming into the market. You mentioned 150,000 horsepower be commissioned. Maybe just talk about are you really be replacing that 150,000? How are the extending maintenance lead times acting accordingly? Just maybe the different pieces that you could talk about to why the 29 coming in shouldn’t spook or scaring any investors because you’d expect some coming out through all the different forms that we’re seeing?

Robert Drummond: Yes, Derek, thank you for the question. We tried to anticipate that more and more after hearing the dialogue in the market. The investor deck we put out last night, I would refer people, I thought this was the best view of it I’ve seen before. On deck Page Number 11, where it shows the rebuild cost versus new build cost and how the salvage value for the old diesel fleet declines each time that you rebuild it, and thereby you reach a point where the return on investment of a new build is better than a return on investment for refurb. And I think the large portion of the diesel fleet is out there in the market, not just ours, but others are in that kind of category. So, you go to the point that you got 29 announced kind of we believe that kind of fall in ’23 new e-fleets, direct drive, and rebuilds in the market.

That’s about as much as it could be. And then, you go and you think about the attrition side supported by what I just said is that even if only 3% of the fleet attrits, that’s saying that the frac fleet lasts 30 years or frac fleet just lasts that long. So, I think when we talk about our horsepower being flat, we talked about having electric fleet coming in and the fact that we’re going to remove and retire 150,000 horsepower over the next 18 months, all of that kind of leads to us saying that we’re going to keep the same amount of supply in the market through ’23 and that we’re going to manage it. And it’s not that we’re being stupid in cutting up equipment, it’s because there’s a better return to do so by replacing it with new build, in our case, electric.

So that’s the logic that I think applies across the whole fleet. And honestly, I honestly believe that that’s not even a choice. The supply chain, the way it is right now, we’re struggling to keep up with the parts needed to continue to do maintenance CapEx. So, I think that’s also systemic across the entire sector.

Derek Podhaizer: All right. I appreciate the comments. And just quickly to follow-up that 150,000 you plan to replace all that, would that be with all electric pumps or do you expect acquire or purchasing more Tier 4 DGB pumps on that 150,000?

Robert Drummond: That’s mostly going to be electric, but I would say opportunistic — opportunity to pick up. These Tier 4 dual fuel fleets that we — the decision we made to make an investment, more and more I think about the more I like it. It’s got a great return profile and it’s maybe better than electric in the long run. The fact that we’ve been kind of going slow on deploying electric has been in our favor, I think. There’s things about the market and how that’s powered that’s getting better all the time, and I feel like the return on these Tier 4 DGB dual fuels is going to be good for a long time. So, we might sprinkle a little bit of that in there with it. But…

Kenny Pucheu: In fact, Derek, we still have roughly about two fleets of Tier 4 that we need to convert to Tier 4 DGB that just slipped from last year due to supply chain. So, in our CapEx budget, we already have two more fleets coming in.

Robert Drummond: But the main thing is you really got to be gas powered to take advantage of that fuel arbitrage, which is a big number.

Derek Podhaizer: All right. No, okay, that’s helpful. And then, for my follow-up, just want to go back to M&A. You talked and — l’ll stick on the consolidator on the frac side. What would that look like for you guys? I mean, I think a lot of these privates have been taken up. There’s not too many out there with real next generation pumps. It’s more of the Tier 2 diesel stuff that’s been taken up off the action blocks. You’ve seen one of your larger peers take out one or two of those. What is consolidation on the frac side look — what are you looking for? Is it just taking those pumps out of the market? Do they have maybe vertical integration aspects or facilities that are attracted to? Just some more color on that would be helpful as far as M&A targets.

Robert Drummond: Yes, I guess you recognize there’s a slight change in what we’ve been saying. And it’s meant to be because of the big factors I just mentioned a bit. I think the smaller your company is, the more challenging it is to tap into an already difficult supply chain. So, some of the deals that perhaps could be available, could have such a good return profile that you can’t ignore. If it came down to a small company that was unable to keep the fleet in the condition at which they wanted to because of lack of access to parts. So, if it was a very quick payback consolidating traditional equipment how arguably would have been ruling that out six months ago that I’d maybe consider today. And the second thing I would say any company that is in the line of the transition from diesel to gas that would help in a comp combined manner would be a logical M&A in the frac arena directly.

Derek Podhaizer: Got it. Very helpful. Appreciate it, guys. I’ll turn it back.

Robert Drummond: Thanks, Derek.

Operator: Our next question today is from Kurt Hallead of Benchmark. Please go ahead.

Kurt Hallead: Hey, good morning.

Robert Drummond: Good morning, Kurt.

Kenny Pucheu: Good morning.

Kurt Hallead: Hey, great color today. Really appreciate it. So, I’m curious, first and foremost, you talked about supply chain and lead times being extended, you kind of reference that on the third quarter conference call as well. So, what are the particular parts or pieces of equipment where you’re seeing those lead times? And are you seeing them extend relative to what they were in the third quarter, or have those lead times kind of stabilized at this point?

Robert Drummond: Kurt, it’s hard for me to be overly specific without maybe hurting myself. And I don’t want to do that. So, I would just say is that relative to Q3, it’s about the same. And I would have hoped it would have been a little bit better. And I would say that think about it being the big components mostly. And I would also say that there’s spots where we’ve made some progress, but there’s spots where we haven’t. I’m talking about the big way all of us in my view. And I think that there is signs of ability to make the difference. But some of that is in with your own control and some of it, you have to be in a partnership with one of your vendors. So, we spend a lot of time now trying to make sure the interface between us and our vendors is as good as it could be just like we do with the interface between us and our own customers.

Kenny Pucheu: And I’ll just add that we’ve been investing in CapEx and inventory just to kind of take control of our own destiny in that space to make sure that we can supply the fleet, probably carry more inventory and CapEx than we would have in the past.

Robert Drummond: And align ourselves with the vendors and helping them to whatever their goals are, we are trying to help them — if it’s better visibility on planning or if it’s front-end payments like Kenny is talking about.

Kurt Hallead: Okay. Got it. So, my follow-up would be your — you mentioned that you have strong conviction in your ability to kind of recapture the lost pricing that occurred during the COVID period, right? So, I’m really just kind of curious on your perspective, right? We have a situation that could evolve, as you mentioned, where you could see 50% of frac activity decline in the Haynesville. I’m not saying that you’re predicting that, just saying that, that’s what happened last cycle, right? And you got, let’s say, those 14 fleets going to try and to find a home in the Permian or another oil basin, that typically creates kind of asset-on-asset competition and kind of puts the negotiating leverage back in the E&P hands, right? So just kind of curious what kind of underpins your conviction or has your conviction changed at all about kind of recapturing that pricing, given what’s going on in the natural gas markets right now?

Robert Drummond: Look, that goes back to the supply and demand balance in frac either you believe it or you don’t. And you think about this time last year, how the dialogue was, what we were saying versus what was being said by many of the E&Ps, that they didn’t realize yet the supply demand balance is what it was or imbalance. So, all I’d say is that whenever there’s a move, regional migration, which has been going on a lot, by the way, in the last year, I mean, even is that the first step or two, you had to have either conviction in it or not. And if you don’t, then there will be some frac companies somewhere that will feel it. But if it’s a balanced market, there will be another home for any displaced fleet. And that point of our customers, I think, understand that better this year than — this time than they did last year.

So, all I’d say is, our track record of kind of looking at this macro is pretty good. We’ve been skating where we said the puck was going to be and knock on wood, we kind of been right about it. So, we’re very cautious about not being wrong about it. But I’ll also say it’s not necessarily that everybody needs to get a price increase. Many times, you get the same impact of a price increase by improving contractual terms that we’re flowing back what maybe conceded in the past around minimums and hours that you would succeed, how you handle white space in the calendar, how is non-productive time managed. And I’d also say that the big dynamic that we often don’t think about when you’re looking at the whole macro is the dynamic for natural gas-powered fleet, natural gas fuel fleets, is way different.

It’s supported by an arbitrage of as much as $10 million of fleet where there’s $10 million that a customer could pay substantially more for a fleet yet show a lower cost. And I saw an E&P recently announced that they were going to make a change in 2023 and they were going to see some deflation. And that’s what they’re talking about, I think, it’s where they are going to be paying a frac company more, and the frac company is going to get a good return and the customer is offsetting it with the lower — his portion of that lower fuel cost. So, it’s a win-win if there ever was a definition of one, and that’s more and more becoming a big part of the fleet. For us, it’s more than half of our fleet has got natural gas support that way. So, I may be talking a little bit of our book overall, but at the end of the day, my comments around the macro sustained that I believe the whole fleet is in that arena and moving out of gas in the oil at this particular part of the cycle is going to be fine.

Kurt Hallead: Yes. And I think what you emphasized here is that there’s a lot more nuance to it in this cycle run than there might have been four, five, six years ago in terms of discussions that you’re having with E&Ps, right?

Robert Drummond: That’s exactly right. And the E&Ps understand that clearly, because they are the ones having the right to check and they can see the fuel cost bills way down and the frac fleet cost up a little bit. But we still — back to that point, not back to our net pricing pre-COVID. I mean we’re not part of the inflation story until we get back to at least that number. So, I feel — we’re not part of the problem here for them.

Kurt Hallead: Got it. That’s great color. Thanks, Robert.

Operator: Our next question is from Saurabh Pant of Bank of America. Please go ahead.

Saurabh Pant: Hi. Good morning. Hey, Robert and Kenny. Just a quick one for me. It’s kind of following up on Kurt’s question on pricing, and I’m trying to understand the full year 2023 guidance. I think if I caught it correctly, you said you expect EBITDA to be up 40% to 50% in 2023, which is basically in line with the implied EBITDA, right, based on your free cash flow and CapEx number, right, it’s about $920 million to $985 million. And I’m just trying to do a EBITDA per fleet math, that implies about $30 million per fleet on a flat 32 fleet basis versus the fourth quarter, right, comparing that with $26 million in the fourth quarter. Can you help us through the moving pieces on how we get from $26 million to $30 million? Basically trying to understand what’s baked into that from a pricing perspective, from an efficiency perspective, and from a website integration perspective?

Robert Drummond: I’m glad you asked that question that way because at the end of the day, I can see how it might be confusing to see that the company is not spending very much money in growth CapEx and being able to demonstrate that kind of year-over-year increase. And when you look at where we are as we exit 2022 and project that on an annualized basis, it doesn’t take very much price or efficiency to get to the kind of numbers that you were talking about. But I do want to try to emphasize one more time about, I wouldn’t encourage people not to get overly caught up on the fleet count, because I think you’ll see ours move two or three up or down during the year with exactly the same amount of horsepower deployed. There is a significant number of fleets operating in U.S. land today that are operating with less than the number of pumps that they would like to have, and the customer would gladly pay for a couple more.

There are cases where deploying horsepower into that kind of arena is better than configuring a bunch of them into a new fleet and going out less than maybe ideal. So, we’re going to be — and our economics, we run on a per horsepower or per pump basis as opposed to per fleet. But long answer — Kenny can get into a little more of the mathematic details there. Just think about it being largely price and building of the already established run rate with the one additional electric fleet hitting the market now in Q2 instead of Q1.

Kenny Pucheu: Look, I’ll just add and just to highlight from our investor deck, it’s not just about EBITDA profitability or EBITDA profitability on a per fleet basis. We’re focused on generating returns and cash flow. And that’s our goal through the cycle is to generate all three, right? And that’s why one of the reasons why we put out that deck is to kind of show some other perspectives around financial performance of both the sector and next year.

Saurabh Pant: Yes. No, Robert, I appreciate you said that because that EBITDA per fleet metrics is becoming increasingly less relevant because the numerator and the denominator are both becoming hard to compare across companies. So, I totally appreciate that point. Just a quick unrelated follow-up. I think you said to somebody’s question, it has benefited you that you have been slow on the electric fleet front, right? I wanted to follow up on that and think through what are you looking at from a technology standpoint? Are there other technologies out there that you are testing, trialing? And then, just on the e-fleet front, how do you think about the leasing versus owning? And what do you think is the right answer for you on that front?

Robert Drummond: Look, I think it depends on the terms for which one is the best all the time. We would be looking at how it impacts our returns to make any decision like that. Technically, I would just say it’s more about the financial around how you power an electric fleet. There’s numerous different electric options out there, but they’re not hugely different when it comes right down to it. I think they’re all going to be pretty effective in balancing lower fuel consumption — or lower fuel cost and lower operating costs in general over time. It’s just that when I said we were going slow, I meant not slow technically, more slow financially, so that we could harvest Tier 4 DGB, and I would just argue, I don’t know when that ends.

It seems like Tier 4 DGB might be a good investment long term, but I think for us that we got to keep balancing that with how power evolves. If you get to a point where there’s a grid out there and there’s a number of customers working in that direction that you can plug an electric fleet in and you don’t have to take the power generation out there, and that’s going to be a really good dynamic for frac financially. So that kind of thing we’re balancing.

Saurabh Pant: Okay. Perfect. And just a quick clarification, Robert. The first fleet that’s coming on in the second quarter, have you said if that’s purchased or is that leased?

Kenny Pucheu: Yes, this is Kenny. So, we’ve said publicly our first e-fleet is on capital lease, about $30 million of its finance and about $10 million in the CapEx budget. Look, we negotiated that about a year ago. We’re very pleased with the terms, and it’s going to allow us to match the cash flow ins and outs. So — but, yes, that’s what our first fleet is.

Saurabh Pant: Okay. Thanks, Kenny. Thanks for clarifying. Okay, guys, I’ll turn it back. Thank you.

Robert Drummond: Have a good day.

Operator: And our next question is from John Daniel of Daniel Energy Partners. Please go ahead.

John Daniel: Good morning, and thank you for including me.

Robert Drummond: Hey, glad to.

John Daniel: Yes. A quick question. I mean, you pointed out rightly the supply chain headaches that are out there. And it sort of begs the question, at what point do you have to start planning your orders for ’24?

Robert Drummond: Well, I’d say…

John Daniel: I’m looking for a specific CapEx dollar number. I’m just asking just a strategy from a procurement standpoint.

Robert Drummond: I think pretty much now, man. I mean at the end of the day, given the visibility to your supply chain and just like our customers can do it for us, it helps everybody plan and organize accordingly. So, I would argue that, yes, that is probably true. And I’d say a lot of people did ’23 very early. We did ’22 very early. And I would say we probably should have moved up ’23 even earlier than we did. But it’s going to — I don’t mind if you order it or not now right now, getting clarity on your ability to catch up. And I think there’s probably more down assets now as a percentage of total than it’s probably that I’ve seen in a lot — ever maybe.

John Daniel: Right.

Robert Drummond: So, they got to catch up with that first and then new builds. So, I’m not even thinking as much risk in ’24 having a lot of wave of new builds coming just specifically because of that.

John Daniel: It would seem to me, and you pointed out the new capacity, and — but when you think about the lead times, companies such as yourself having the wherewithal to place orders now to be in the front of the queue, just seems like the larger companies in theory, it sounds — it’s not meant to sound anticompetitive, but you can tie up the supply chain a bit more — and it does limit, if I’m not mistaken, the number of new entrants that could actually practically come on into the market. I don’t know if you would care to comment on that, but it just seems reasonable to me.

Robert Drummond: Yes. I think it sounds reasonable to me as well, John. I’d just say that I think I’ve seen it play out a little bit in the market. When you look at maybe some of the M&A deals that have been done with smaller guys who basically had seen their fleet count drop over time against their will maybe, because the — unable to access the parts necessary to keep the whole thing running. I think extrapolate that into your question, I think that’s the same answer.

John Daniel: Okay. Can I squeeze two quick ones in here real quick? I don’t know if you got a long line behind me.

Robert Drummond: Yes. We — this is our last question. I mean, you’re the last guy. So, let’s go ahead.

John Daniel: Thank you. So, when — in the incremental demand of 20 to 25 fleets, I’d hate to be nuanced, but how much of that is actually truly for dual fuel versus legacy Tier 2? Does that make sense? So, it seems like more of the demand…

Robert Drummond: Well, look, I would say that we ain’t looking at it like, yes, there’s a macro or the fleet count. If the customer had a choice, it would be 100% dual fuel or electric, whatever can burn natural gas, put it that way.

John Daniel: Fair enough. And then last one, can you just update us on sort of your thoughts on any differences, competitive differences between Delaware and Midland Basin what you’re seeing sort of leading edge out there?

Robert Drummond: From what perspective?

John Daniel: Just from activity, from thoughts of competitors maybe shying away from Delaware Basin type work because of it more in intensity, if you will, on the equipment, just have you seen any demonstrable change in competitive landscape? And what would you expect…

Robert Drummond: I think everybody is looking for who can get the best kind of efficiency pumping hours per fleet per month on average. We made a number of changes in our home fleet as we went into ’23 and some of that was migration within the basin, looking for customers of likeminded that were focused on — the whole supply chain working in unison and absorbing the integrated model and being able to pump in day in and day out. The difficulty of the frac is a factor in there for sure, and it has to be captured either in price or something or you would have differential performance financially one frac fleet to another and hard versus easy fracking. So yes, I suspect there’s some of that.

John Daniel: Fair enough. I appreciate you making time for me.

Robert Drummond: Thank you. Appreciate the call.

John Daniel: Yes, sir.

Operator: This will conclude our question-and-answer session. At this time, I’d like to turn the conference back over to Robert Drummond for any closing remarks.

Robert Drummond: Thank you very much, everyone, for participating in today’s call. I really do want to thank the entire NexTier team for your efforts, and we remain committed to making NexTier a place where you’re going to find opportunities for a long and fruitful career. Thank you very much.

Operator: The conference has now concluded. Thank you for attending today’s presentation, and you may now disconnect.